The Southern Company (NYSE:SO) Q3 2024 Earnings Call Transcript

The Southern Company (NYSE:SO) Q3 2024 Earnings Call Transcript October 31, 2024

The Southern Company beats earnings expectations. Reported EPS is $1.43, expectations were $1.34.

Operator: Good afternoon. My name is Julian, and I will be your conference operator for today. At this time, I would like to welcome everyone to Southern Company’s Third Quarter 2024 Earnings Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce Mr. Greg MacLeod. Thank you. You may begin.

Greg MacLeod: Thank you, Julian. Good afternoon and welcome to Southern Company’s Third Quarter 2024 Earnings Call. Joining me today are Chris Womack, Chairman, President and Chief Executive Officer of Southern Company; and Dan Tucker, Chief Financial Officer. Let me remind you that, we will make forward-looking statements today in addition to providing historical information. Various important factors could cause actual results to differ materially from those indicated in the forward-looking statements, including those discussed in our Form 10-K, Form 10-Q and subsequent filings. In addition, we will present non-GAAP financial information on this call. Reconciliations to the applicable GAAP measure are included in the financial information we released this morning, as well as the slides for this conference call, which are both available on our Investor Relations website at investor.southerncompany.com. I’ll now turn the call over to Chris Womack.

Chris Womack: Thank you, Greg. Good afternoon and thank you for joining us today. Our entire company including our premier state-regulated electric gas and utilities, continued to perform well during the third quarter, especially as our dedicated employees across Southern Company came together as one team in response to Hurricane Helene. The resolve and the professionalism of our employees has never been more evident than was demonstrated through the recent storm restoration efforts in Georgia. Before Dan provides an overview of our financial results, I’d like to share our story from this unprecedented weather event. Hurricane Helene was a storm of historic magnitude. Its aftermath was met with an extraordinary response from our dedicated team across Southern Company, our mutual assistance partners, state and local first responders and emergency management agencies and government officials, all across Georgia.

Persistent rain, extreme flooding and heavy winds resulted in what can only be characterized as devastation to many of the communities we serve, with the destruction stretching hundreds of miles impacting the Eastern two-thirds of the entire state. Ultimately, the damage caused by Hurricane Helene was the most destructive in Georgia Power’s 140-year history, exceeding the damage caused by the largest — the three largest storms to impact Georgia Power’s service territory combined. Helene entered Southern Georgia as a Category one hurricane and resulted in 53 out of the 159 counties in the state being declared major disaster areas by the Federal Energy — Emergency Management Agency. With considerable damage to transmission infrastructure, nearly 12,000 damaged utility poles and some 1,500 miles of downed wires, the equivalent of the distance between Atlanta and Phoenix, Arizona, our customers’ experienced over 1.5 million outages in the wake of the storm.

With the support of resources from across North America, a workforce of well over 20,000 worked around the clock to safely reconnect customers through extremely difficult conditions. Commensurate with the devastation seen in our communities, much of our utility infrastructure was damaged beyond near repair, and significant portion of our system in the affected regions require a complete rebuild. Thanks to the contributions of our utility industry partners and especially thanks to the unwavering commitment of our own hard-working dedicated crews, many of whom lived in the same communities and some of whom endured destruction to their own homes, the restoration and rebuilding efforts were 95% complete within eight days with power restored to over 0.5 million customers within the first 48 hours.

We are incredibly proud of our team’s response and eternally grateful to be a part of an industry that works so well together in times of need. Many of the communities we are privileged to serve across Eastern Georgia have a long road ahead to recovery, Georgia Power, Atlanta Gas Light. Southern Company are contributing to organizations to aid these communities and Georgia Power has taken additional steps to provide support and resources to our customers in Georgia. In our business model, customers are at the center of everything we do. And our commitment to the communities and customers we serve has never been more important than in times like these. I am extremely proud of our team’s exceptional efforts to clearly demonstrate that we are a citizen wherever we serve each and every day.

Dan, I’ll now turn the call over to you for a financial update.

Dan Tucker: Thanks Chris and good afternoon everyone. Before I walk through the third quarter financial results, I’d like to briefly address the costs associated with the recovery efforts Chris just described related to Hurricane Helene. The initial estimated cost for this historic storm-related restoration and rebuild is approximately $1.1 billion. The unprecedented destruction associated with this weather event combined with impacts of inflation on the cost of contract labor, supplies, food, fuel, and lodging contribute to the overall cost. Our estimate is subject to change over the next several months as estimates are replaced with bills from our mutual assistance partners as we complete the final cleanup of damaged equipment and as we work to ensure the impacted areas are restored to meet our standards for long-term reliability.

That is not to suggest that our estimate is likely to materially change, but rather to acknowledge that it takes time to fully capture the ultimate cost of such an extensive endeavor. Turning now to our financial results. For the third quarter of 2024, our adjusted earnings were $1.43 per share $0.01 higher than the third quarter of 2023. The primary drivers of our performance for the quarter compared to last year were continued investment in our state-regulated utilities and customer growth. This was mostly offset by higher interest, depreciation, and other operating expenses. And for the nine months ended September 30th, 2024, our adjusted earnings per share were $3.56 compared with adjusted earnings per share of $3.01 for the same period in 2023.

One of the largest drivers in our year-to-date results compared with the prior year is weather-related impacts from an extremely mild first half of 2023, contrasted with the weather effects we’ve experienced thus far in 2024. A complete reconciliation of the year-over-year earnings is included in the materials we released this morning. Our adjusted EPS estimate for the fourth quarter is $0.49 per share, which combined with our year-to-date performance, would represent full year adjusted earnings of $4.05 per share. After excluding a 0.4% negative impact of lost sales that resulted from the damage caused by Hurricane Helene, weather-normalized total retail electricity sales were essentially flat compared with the third quarter of 2023. The broad strength of the economy in the Southeast was exhibited in the quarter by strong electricity sales in the chemical, pipeline, and transportation segments, as well as data center power usage which continued its positive trend and was up 10% year-over-year.

And while weather-normalized residential electricity usage per customer was slightly down in the quarter, we saw strong residential customer additions of 12,000 in our electric businesses and 7,000 new customers in our natural gas distribution businesses. The economic development activity across our electric service territories remains robust and our pipeline continues to grow at an historic pace. 42 companies either established or expanded operation in our service territory in the third quarter generating 5,000-plus potential new jobs and representing capital investments totaling approximately $2.6 billion. Alabama Power’s economic activity this quarter, represented its strongest quarter in several years led by announcements in metals, renewable energy and the chemicals segment.

The combined pipeline for new industrial and other large load commercial customers across our three-state electric utility footprint continues to grow. The upcoming quarterly large load economic development report to be filed with the Georgia Public Service Commission, is expected to reflect that Georgia Power’s potential load additions and its economic development pipeline have grown to over 36 gigawatts, by the mid-2030s with 8 gigawatts committed. Chris, I’ll turn the call back over to you.

Chris Womack: Thanks, Dan. We have delivered exceptional operational and solid financial results through the first three quarters of the year, and we are well positioned to finish the year strong. Our team’s resilience in the face of a historic storm, highlights our dedication to the customers and the communities we are privileged to serve, and I am so extremely grateful and proud to be a part of their team. It is certainly an exciting time for our great company and for this industry. With supportive states and constructive regulation, along with our portfolio of state-regulated electric and gas utilities, we are well positioned for the opportunity presented by this extraordinary energy demand growth our industry is projecting in the coming years.

As we work to help our states grow and partner with the communities we are privileged to serve, our disciplined approach, combined with the orderly planning and regulatory processes, across our utility service territories, should support mutual benefits for all of our stakeholders including, our existing customers. Let me conclude by saying, I am very excited about our future. Operator, we are now ready to take questions.

Q&A Session

Operator: Thank you. We will now be conducting a question-and-answer session. [Operator Instructions] Our first question comes from Carly Davenport, Goldman Sachs.

Q – Carly Davenport: Hi, good afternoon – Thanks for taking the question. Maybe just to start on the storm cost side. I appreciate the color on the kind of $1.1 billion estimate at this point. Will all of that be deferred? And can you just talk through the process and the timing for filing for recovery of those costs in Georgia?

Dan Tucker: Yes. And pretty usual, Carly, we don’t want to get too far ahead of any upcoming regulatory processes or make assumptions about how the commission will ultimately decide to deal with it. Just I think it’s good to acknowledge historically. They’ve been very constructive, and the recovery has been timely and balanced kind of the needs of the company and the customers. In terms of where we sit today, yes, all the costs have been deferred. There is still work to do not unlike just turning estimates into more firm numbers. Again, don’t expect material changes there. There’s also — we will also go through a process of determining particularly based on the nature of this rebuild that occurred, not just restoration, how much of these dollars are ultimately capital dollars essentially new assets, as opposed to the cost to support the crews, cost to simply rehang wires, those look — would typically look more like O&M, but those will be deferred and potentially recovered in a different manner than the capital cost.

Q – Carly Davenport: Got it. Okay. That’s super helpful. Thank you. And then maybe just pivoting to the load growth side. I appreciate the updates there on the pipeline in Georgia. Could you just talk a little bit about, how that pipeline has developed and also the commitments? In the context of the upcoming IRP filing in Georgia, how are you thinking about the potential magnitude or mix of that filing just based on what you’ve seen so far, in terms of, how that large load pipeline has developed? And how that pipeline has converted to actual customer commitments?

Dan Tucker: Yes. That’s a great question, Carly. So — and again, without getting too far ahead of any processes or actual filings, the reason that Georgia Power is making this quarterly filing with the PSC was really to help all parties have a little bit better line of sight leading into the next formal process. And so since, we began that process, we’ve seen not only momentum continue and the size of the pipeline, but we have, to your point, seen continued commitments within that pipeline. So as we sit here today, again, we have 8,000 megawatts that have been committed by the kind of mid-2030 time frame, whereas at the time of our filing last fall with the Public Service Commission, that number was more like 3,600 megawatts. And so we’re continuing to see that kind of progress.

Chris Womack : Carly, one thing I would add, and we talk about it a lot as we go through kind of our narrative about how this process works and I talk a lot about our orderly processes. And I think, as you look forward to this next large load filing and then as the company prepares for the Integrated Resource Planning process, I think that demonstrates that process that’s in place to clearly demonstrate what’s real. And then how we price this and just how we work our way through bringing these projects online, but just working through an orderly process, because there’s a lot of activity up in the marketplace. But I think we owe it to our regulatory bodies, but also to all of our states to make sure we’re being very diligent as we work through this process to bring these projects online.

Carly Davenport : Got it. Very clear. Thanks so much for time.

Operator: Thank you. Our next question comes from Shar Pourreza of Guggenheim Partners.

Shar Pourreza : Hey, guys, Chris and Dan.

Chris Womack : Hey, Chris.

Shar Pourreza : Hey, Chris. I just wanted to maybe start with Southern Power for a second, sort of this kind of push for resource adequacy being so front and center in almost every jurisdiction. I mean Southern Power is predominantly contracted, but I have to imagine kind of the offtakers want to stick with the assets. Are you seeing kind of any opportunities around restriking the contracts and extending the tenors? Are you seeing opportunities as contracts roll off? And how do we think about pricing kind of in this environment and what it could also mean for Southern Power’s growth? Thanks.

Dan Tucker : Yes. Let me start, Shar, and just level set on Southern Power. So we’ve always taken approach to Southern Power to have it — have a risk profile that looks and feels like the regulated business. So long-term contracts, creditworthy counterparties, we don’t take fuel risk. And so that portfolio, and in particular, if we focus in — on the natural gas generation portfolio, is largely covered, I mean, 90%-plus covered through the end of this decade. And so it’s not until then that you begin to have contracts that are up for renewal. Now obviously, we would have an opportunity to renew or extend to your point well before the end of the decade. And so in that context, as we look at the current contract rates relative to what capacity values appear to be out in that time frame, they’ve essentially doubled relative to what they were.

Again, this is a long-term opportunity to kind of improve the returns within Southern Power. So yes, there is great interest in that capacity. Beyond the existing assets, we’re also getting pinged, if you will, continuously by customers, hoping to be able to add new assets, whether those be natural gas or renewables, whether that’s in the Southeast or in other markets, particularly where we have renewables. And it’s the same kind of potential customer mix that we have today. We serve a lot of load-serving entities. So, investor-owned utilities, municipalities, co-ops. But we also, particularly in our renewable portfolio, serve a lot of large commercial and industrial customers directly through contract. They may be in structured markets, but it’s ultimately a contract with an individual customer.

So we’re exploring those too, but maintaining that same discipline I described on the front end, long-term contracts, creditworthy counterparties, no fuel risk.

Shar Pourreza : Got it. But that discipline doesn’t really curtail or put a ceiling on how big you expect Southern Power to get, because the opportunities are pretty sizable?

Dan Tucker : Yes, I think that’s right, Shar. And just historically, and I think even going forward, we are a regulated utility holding company and we have this incredibly attractive complementary wholesale generation business that we’ve never wanted to get outsized relative to our retail business, our retail electric business or in gas business. That said, the regulated utility business is growing so fast right now. I have no concerns about Southern Power’s growth rate outstripping that.

Chris Womack: But Shar, just always remember we talk about being disciplined. And just know that in the midst of all this opportunity we will remain very disciplined as we move through this period.

Shar Pourreza: Got it. Okay. Perfect. And then just lastly just on follow-up on Carly’s just fine-tuning. Just Dan, do you have any sense you’ve got an estimated cost number there. You said $1.1 billion it could change. But do you have any sense on how much of that could be capital versus O&M? And then how do we sort of think about the timing of that recovery going into a GRC, as we’re thinking about bill impact and customer affordability right? So there’s a bunch of things happening at once and this is a big GRC coming up. So how do we sort of think about the risks there?

Dan Tucker: Yes. On your first point Shar, it’s just too early to say. I think intuitively, we believe it will likely skew at least a little more capital than historically. But in terms of what that actually looks like, it’s hard to say. And the reason that that’s our belief is simply because of the magnitude of rebuilding that occurred in this storm. And then in terms of the process, again you know us and go back to Chris’ comments. We’re going to remain disciplined and part of our discipline is not getting ahead and making assumptions about what our regulatory processes will be. There’s going to be lots of variables, not only the split of the capital versus this other piece, but just what else is being considered at the time. And I think the most important thing to look back on is the constructive approach that the commission has taken historically.

Shar Pourreza: Perfect. I appreciate it guys. Thanks so much.

Dan Tucker: Thanks, Shar. Take care.

Operator: Thank you. Our next question comes from Ross Fowler, Bank of America.

Dan Tucker: Hey, Ross.

Ross Fowler: Good morning, Chris, good morning, Dan. So maybe following on the Shar’s question he asked most of it. But Dan, maybe not commenting on whatever happens in the future. But in the past sort of as you work through storm recovery processes in Georgia, this isn’t first hurricane you’ve ever had. What is the typical sort of cash recovery lag? Can you remind us what that looks like? And then does that create an opportunity for securitization? Can that be done in the state? And then how do you sort of finance the gap between kind of the expenses that have gone out on the balance sheet versus the actual cash recovery this going forward?

Dan Tucker: Yes. Look I think the PSC has in their hands every tool of their disposal to overlay kind of a flexible approach to this. Without being too precise about the history, I think it’s fair to say it has dependent on the magnitude of the storm and the circumstances at the time, but the recovery periods have been from a couple of years to as many as six years depending on how big the balance was and what else was kind of being factored into rates at the same time.

Ross Fowler: Okay. Perfect. Thank you.

Dan Tucker: You bet.

Operator: Our next question comes from Nick Campanella, Barclays.

Dan Tucker: Hey, Nick.

Nick Campanella: Hey. Good afternoon, everyone. Thanks for taking my question. Hope everyone is doing well. So I just wanted to kind of get your perspective 36 gigawatts is a big number. You already have eight committed to your point. It just kind of seems like there’s pressure higher on your load outlook every quarter here. And you have seen some peers in the space starting to kind of revise numbers specifically kind of EPS outlooks on this. And I’m just kind of curious, is there a tipping point for you into where you would essentially need to kind of reevaluate the 5% to 7%? Is there a point where the plant can sustain a rate base growth figure even that kind of financing drag that would kind of put you above that 5% to 7% range? Thanks.

Dan Tucker: Sure. So I’ll start Nick with what I’ve said historically on the growth rate. I would not expect anything to change in the near term everything we’re describing. So let’s go back to the 36 gigawatts that we’re referring to. That’s by the mid-2030s. That’s not a 2024, 2025, 2026 kind of phenomenon. That’s long term. There’s certainly — it certainly gets feathered in through the end of the decade and then well into the next decade. But every opportunity that exists here for acceleration of anything is long term in nature. And what I’ve said historically is to the extent this momentum continues, and the momentum is less about the pipeline as it is the commitments and the risk-adjusted outlook on sales and the capital that it takes to serve the load.

If that continues, long term, in the latter half of our outlook, there may be an opportunity to reevaluate where the growth is starting from. As we sit here today, I don’t think five to seven as a rate of growth changes. But again, we will evaluate it when we get there. You mentioned a lot of the moving parts here. We shared earlier this year that our long-term sales growth or at least the back half of the plan was close to 6%. With everything we’re seeing, when we update our plan in February for you all, I won’t be surprised if that’s a higher number. When we get to February, we’ll unveil our capital plan. We’ve already talked along the way and disclosed in our Q several things that are incremental to our capital plan earlier this year, handful of Southern Power projects, little bit of refinement around the Georgia Power IRP process, that IRP update around storage and the cost of plant Yates and its certification.

We’ve seen the details around the Southern Natural pipeline opportunity that we own 50% of. Those things on their own that are known are roughly $3 billion of incremental capital relative to our $48 billion plan. It won’t surprise me, given what we’re seeing, that there are several billion dollars on top of that reflected in our plan in February. So we’re taking a long-term view here. There’s lots of opportunity. We’re being very disciplined about how we approach this.

Nick Campanella: That’s great, Dan. I appreciate all that context. Thank you for that. And I know the IRP filing is coming. You guys have been kind of leader in the nuclear space. Can you just kind of talk about how this fits into the company’s wider generation outlook, even if it’s not kind of the consolidated level? Are there re-licensing opportunities? Are, there uprate opportunities to consider? And there was discussion about potential multi-state framework? Is that something that you are part of? Maybe you could talk about this a little bit. Thanks.

Dan Tucker: Yes. Look, there’s obviously a lot in that question as well. Let’s just put it in the context of the IRP, just not going to get ahead of any regulatory processes, but let’s talk about what that process looks like, right? It’s — at the end of the day, it’s reflecting and projecting out scenarios under various moving parts, environmental rules, the cost of natural gas over time, the cost of capital over time. And those scenarios are solving for the most economic, reliable way to serve customers in the long term. Is it possible that one of those scenario model runs, spits out a nuclear uprate or a new nuclear unit as the solution in the model? Sure, it might. Does that mean that’s a recommendation? No. Does that mean that’s a path we’ve embarked on?

No. Does that mean it’s an option that is worth preserving and considering down the road? Of course, it is. But there’s a lot that’s going to take place before we get to that point. And that’s, I think, what you hear a lot of us in the industry talking about. Aq New nuclear is super important for them for this country, but in order to get to the right place, there’s got to be better risk mitigation than exists today. That’s got to come from changes with the federal government, that could come from some of these conversations with these large technology companies. We’re talking to as many of these companies as anyone. I’d argue we’re having conversations with the majority of them, not just around nuclear, just around different ways to solve for this load equation.

So it’s a part of a broader conversation, but our discipline around this, and I’ll tell you as my discipline as CFO, we’re not going down that path until the risk is mitigated. But Chris, what would you add?

Chris Womack: Yeah. No, Dan, I think you’re exactly right. I mean there’s a lot of work that needs to be done at the federal level if this country is to embrace more nuclear. I mean — and Dan said it. I mean, Southern Company has engaged with, over majority, maybe all of the hyperscalers regarding nuclear solutions, but other solutions to respond to their data center needs, but there are just so many risks that have to be dealt with. I mean, the risk is simply just too great. There’s a ;lot of work t I mean, I am hopeful and we are trying to encourage to make sure that the government leans in a manner that helps mitigate the risk to shareholders and existing customers. But we’re not going to move forward until we see a better line of sight in terms of those risks being mitigated.

But between the federal government and some of the hyperscalers and we hope we can see hope there’s progress and advancement on responding to what needs to be done but also helping mitigate some of this risk.

Nick Campanella: I appreciate your perspective on it and look forward to see you in Florida. Thanks.

Chris Womack: Great. Thank you very much.

Dan Tucker: Thank you.

Operator: Thank you, sir. Our next question comes from Jamieson Ward, Jefferies.

Unidentified Analyst: Hey, guys. It’s Julien here actually. Thanks again for taking the question. Maybe to follow up on Nick’s last one here if you can just elaborate a little bit further here on the nuclear side. I mean clearly a lot of focus. You guys obviously led the Vanguard here at the outset of the last build-out cycle. Can you speak a little bit more — you talked about preserving the option over time. That doesn’t sound like it’s kind of a nearer-term development that you could press release in the next year with the hyperscaler precise. I just want to make sure I’m hearing this right. This is more preliminary than maybe what we’ve seen from some of your peers out there? I don’t want to put words in your mouth. I’m just sort of curious to tease out of you how far down that rabbit hole you are considering the expertise that you guys bring to the table on the subject whether an SMR or [indiscernible] down.

Chris Womack: No. I think you said it upfront. I mean we’ve had — with Vanguard. We’ve had this experience and we recognize and fully understand the risk that are there. And so as we spoke earlier we think before we can move down this path we’ve got to find solutions to mitigate the risk to our shareholders but also to our customers with nuclear. And so that’s kind of where we are. I mean we’ll go through the IRP processes that — and as we go through those models and all the different scenarios in terms of what may come forward. But from a nuclear perspective the risk issues are just so real and we know what they are that we’ve got to find some way to mitigate those issues before we see the opportunity we see the reality of moving forward.

Operator: Okay. Thank you. Our next question comes from Jeremy Tonet, JPMorgan.

Chris Womack: Hey, Jeremy.

Jeremy Tonet: Hi. Good afternoon. Happy Halloween. If I could just continue on the nuclear side a bit here. And I know you touched on uprates there a bit. But just wanted to see at a high level if you could share any thoughts at all as far as what the opportunity set the range of I guess uprate potential there. And I know that there’s a lot of variables in play economics and all the other factors that you’ve listed. Just wondering directionally if you could give us any thoughts there?

Dan Tucker: Yes. Look again Jeremy — I hate to keep — we’re not going to get ahead of any regulatory processes. I’ll give you just a little color there. So broadly across the enterprise so this is not Georgia-Power specific, but Georgia Power and Alabama Power and we have co-owners on all of these things. We do have six legacy units that there are opportunities for up rates. Historically, many of those uprates have not been economic. The benefits that are inherent in the IRA and some of the other legislation help with that and are pushing them to a point where they are potentially more viable not that they don’t require a significant amount of capital not that they don’t require a significant amount of time, but certainly don’t bring with them the kind of risk of a new nuclear project. So it is certainly something on the table that we are evaluating. And at the right time we’ll put that forward as an option if appropriate.

Jeremy Tonet: Great. Thank you for that. And then I just want to kind of shift gears given the big call on generation as you’ve outlined there. Just wondering any thoughts you could share with I guess coal retirement time lines? What could be impacted there? And then even as it relates to carbon capture is that something that you see as plausible for coal or gas? Or just any thoughts as it relates to Southern?

Chris Womack: A couple of things. On coal retirements clearly we’re watching and paying attention to the EPA rules and we’ll — that will clearly instruct and inform us as we go through planning processes in terms of what those — what the life of those projects will look like. So that’s a couple of things that will of course continue to pay attention to. And what was the second part of your question?

Jeremy Tonet: Just as it relates to carbon capture potential for both the coal and gas.

Chris Womack: So as you know we’ve been operating the national carbon capture center now for some 50 years. And so we initially were doing a lot of carbon capture research around coal. We have shifted that research now to gas. And we have a number of partners from the utility industry, but also partners from the oil and gas industry because we all recognize the vital role that natural gas will play in this economy and supporting electricity generation and knowing how important it will be to bring forth technology for carbon capture as well as sequestration. We continue to pursue this work. We know there’s more research to be done to get this at a point where it’s scalable, but we’re going to continue to make this investment because we think gas will be essential for this country going forward. And we’ll continue to invest in international carbon capture center, but also find other research opportunities to invest in carbon capture and research carbon capture.

Jeremy Tonet: That’s very helpful. And one last quick one if I could sneak it in. Just as it relates to the pipes opportunity as you laid it out there, I think it was part of the $3 billion there. But just was wondering I guess, if you could provide a little bit more color on what that could look like just size of gas you’d like to get into your service territory? And what type of time frame do you see this ultimately unfolding over?

Dan Tucker: Yeah. So there’s a lot of details there on the gas procurement side Jeremy that we can’t share. I mean that’s proprietary information that’s part of the project. There are contractual provisions between Southern Natural and all the off-takers. Suffice it to say, the existing Southern Natural pipe, our entities between our electric generation fleet and Atlanta Gas Light and the marketers in Georgia represent 50% of the offtake of the existing pipe. And so I don’t think it’s unreasonable that with an expansion project that we have the opportunity to be a pretty large participant as well. As far as the timing of the project, again, I think all these details are probably out there in Kinder Morgan’s materials. But just think about it essentially as a project that culminates sometime at the very back end of our forecast or late this decade.

Jeremy Tonet: Got it. Very helpful. Thank you.

Dan Tucker: You bet.

Operator: Thank you. Our next question comes from Paul Fremont, Ladenburg Thalmann.

Chris Womack: Hi, Paul.

Paul Fremont: Hi, thanks. Thanks for taking my question. Would you consider at this point adding fossil generation at Southern Power given the significant demand that you’re seeing for customers to add capacity?

Chris Womack: Yes. I mean — and Paul, Dan has referred back to our model as we think about Southern Power. And so that will guide a lot of work that we do in consideration of that we have. I mean, and so as we look at projects we look at creditworthy counterparties not taking fuel risk, but using that kind of discipline to guide what happens at Southern Power going forward, I think will instruct us in terms of what opportunities that may be available and what things we’ll pursue. But I think it will be premature to make any kind of commitment or any kind of guidance in terms of what may happen there.

Dan Tucker: Yeah. If you think about the conversation we’ve already had along the way here, environmental rules, things like 111(d) and what happens there, pipeline infrastructure and its availability to do projects like that. If we can mitigate those risks or the contract is designed in such a way that more than pays for those risks then that’s something we’ll continue to keep on the table. So it’s never, no. It’s just a function of being consistent with our business model.

Chris Womack: And I think it’s also being — remaining disciplined. I mean there’s a lot of enthusiasm in the marketplace today. But we’ve got — as you’ll hear me say a lot we’ve got to remain disciplined. We’ve got to be true to kind of who we are and kind of our philosophy and values that we have in place and let that guide us as we move through kind of this incredible growth opportunities that we see here in this industry. We’ve got to remain disciplined.

Paul Fremont: And I guess you’ve identified sort of eight gigawatts of committed load including 3.6 gigawatts that were included in the last IRP. So how much of the 4.4 remaining should we assume is paid for by an individual customer versus being socialized over your entire retail load?

Dan Tucker: Substantially all of it by specific customers.

Paul Fremont: Okay. So it wouldn’t — most of it would actually have a positive impact then on customer bills?

Dan Tucker: Yeah. That is the objective as we overlay this disciplined and orderly process that there are mutual benefits of serving this load to the existing customer base.

Paul Fremont: And then last question for me. We’ve seen sort of endless legal challenges to new pipelines would an expansion of SONAT be subject to legal challenges? Or how should we think about that?

Dan Tucker: I think you have to believe it certainly has its susceptibilities as well. And I think that’s again factored in the way Kinder Morgan is thinking about the timeline.

Paul Fremont: But you would need additional permitting and all the things that would sort of potentially lead to a legal fight?

Dan Tucker: Yeah. There’s about 90% of this particular project is brownfield largely compression and looping. And so that greatly de-risks the opportunity doesn’t mean there’s a not still requirement, but you’re not creating a brand-new right of way for hundreds of miles and building new pipe.

Dan Tucker: Great. Thank you very much.

Dan Tucker: Thank you.

Operator: Our next question comes from Durgesh Chopra, Evercore ISI.

Durgesh Chopra: Hey Dan. Good afternoon. Thank you for giving me time. Hey just a blue sky question. Just what you guys think of the SMR technology? Obviously you’ve seen several announcements that your peers have made which are dated at the end of the decade. But what do you — what is your experience with the technology? Have you had any discussions? Do you think it’s scalable? Just kind of your position as a nuclear power operator I’d just be curious on what do you think of the technology itself? Thank you.

Chris Womack: Yeah. Durgesh, this is Chris. And you’ve heard us talk before about our research and development organizations and the proprietary research that we do. And we have partnered with a number of organizations for years, investing in SMR technology, researching SMR technology and Advanced Nuclear. And we follow it. We work very closely with a lot of partners. I mean there’s a lot of work being done, but there’s very few projects that are moving forward. There’s a lot of discussion about them, but I think there’s just a lot more work to be done to finalize the designs and finalize the engineering. And we’re following it and involve very closely. We think it’s very beneficial for us to follow but also to be engaged on multiple fronts I mean even as we were building Vogtle Units 3 and 4.

We continue to involve ourselves with Gen IV an additional advanced nuclear technology. I mean that’s kind of who we are and what we do as a company and we’re going to continue to do that. But from my perspective, there’s still more work to be done before we get close to anything commercial. I mean but there’s a lot of talk out there, but I think there’s more work and more design work and more engineering work to be done.

Dan Tucker: Given that approach I think what it would be fair to say is that we view it as too early to put all of our eggs in one nuclear technology basket.

Durgesh Chopra: Very clear guys. I appreciate that added color. Thank you.

Chris Womack: You’re welcome.

Operator: Thank you. Our next question comes from Travis Miller, Morningstar Inc.

Travis Miller: Good afternoon. Thank you. A quick follow-up on the storm costs. Did you have any storm cost reserves? Or how much did you use of those that was available?

Dan Tucker: There was not a reserve going into the storm. We actually had a very small balance to be recovered. So, this was additive to that. If you actually look at the balance the balance is closer to $1.2 billion whereas this particular reserve was $1.1 billion.

Travis Miller: Okay. Okay. And then higher level to serve that demand that you’re talking about especially that 8 gigawatts if you were to decide to build say a gas unit or whatever today, in terms of supply chain, how long would it actually take you to get from concept today to flowing electrons to a new customer?

Dan Tucker: Well, I’m going to start and Chris jump in here. But I think in answering the question, I don’t want to answer the question as though we haven’t already done things to get ahead of that. So, you — we’ve taken the opportunity to get in the queue for long-lead time equipment. We have partners from an EPC perspective that we’ve worked closely with very recently and very successfully. And so we’re I would say several steps ahead on that. But then you have to step back and say what technology. So, is it a combustion turbine? Is it a combined cycle? Those are different time lines. All that to say, Travis, I think we’re in good shape. It’s in general a three to five-year timeframe to kind of get gas generation from the beginning to the end. And given the long lead time nature of this load we’re pretty well positioned.

Chris Womack: Yes. And I think if you look back at our Barry 8 Project at Alabama, that was a little bit over three years, I think in the construction of that unit so 800 megawatts combined cycle unit. So, we’ve had some good experiences of late with construction of those units.

Travis Miller: Okay, that’s great. And then what about T&D, is there any difference in terms of supply chain or timing of supplies T&D versus generation?

Dan Tucker: No, I think it all overlays pretty nicely. Our lead-times on large transformers and other major equipment longer than they used to be, yes. But we have visibility into that and are planning accordingly.

Travis Miller: Okay, perfect. I appreciate it.

Operator: Thank you. And our next question comes from Paul Patterson, Glenrock Associates.

Paul Patterson: Hey. Happy Halloween. So, it sounds like you guys are — things are falling into place and everything. And it sounds like you guys are — I mean — just to make sure that I’m understanding it correctly that you guys see upside to the sales growth expectations that you previously had and obviously CapEx associated with that, correct?

Dan Tucker: Yes.

Paul Patterson: Okay. And that would — in terms of in the past, when you guys talked about this earnings increase — I’m sorry, this sales growth increase, et cetera. There wasn’t necessarily a direct impact on earnings that you had seen. Should we think that perhaps with this more robust outlook that might be coming out that? How should we think about that in terms of earnings I guess?

Dan Tucker: Yes Paul, I’ll go back to what I said earlier. To the extent we do indeed see this momentum is continuing and we do maintain our discipline about not getting too far ahead or ahead at all of any of the regulatory processes and the line of sight on this stuff. The opportunity to reflect and provide a different outlook will not occur until the latter half of our plan. All of this is long-term in nature. There’s — as exciting as this is and as much work is happening around all this for us and the entire industry, this load is on the back end of the forecast. It’s not this year. It’s not next year. It’s 2028, 2029, 2030 and beyond.

Paul Patterson: Okay. I just wanted to make sure that. I don’t know. I thought maybe I just want to make sure if there was anything else I should be looking at. Okay, that’s awesome. And then just finally on the deferral — excuse me, on the storm costs. When you’re deferring the cost is it at a cost of — I mean I assume you’re getting some sort of return. Is that return a debt return? Or is it — how should we think about the return that’s associated with the deferral?

Dan Tucker: Yes. It’s typically been our cost of capital. But again, with the magnitude of it and with the nature of it, the commission has flexibility to adjust that just like they have done historically with us for other things with large under-recovered fuel balances have a different financing costs associated with it.

Paul Patterson: Okay. Thanks so much. I really appreciate.

Dan Tucker: You bet, Paul.

Operator: All right. Thank you. That will conclude today’s Q&A session. I would now like to turn the call back to Chris Womack for closing comments.

Chris Womack: Again, let me thank each one of you for joining us today. We are — as we said we’re excited about where we are in the company and we’re pleased with the performance we’ve had through the first three quarters of this year. And so once again, we thank you for taking time to be with us and we wish all of you a happy Halloween. Thank you very much.

Operator: Thank you. That will conclude today’s teleconference. You may disconnect your lines at this time.